UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended: June 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________________ to _________________
Commission file number: 1-10671
THE MERIDIAN RESOURCE CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS 76-0319553
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
15995 N. BARKERS LANDING, SUITE 300, HOUSTON, TEXAS 77079
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-558-8080
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 and 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] NO [ ]
Number of shares of common stock outstanding at August 5, 1999 45,903,532
Page 1 of 28
<PAGE>
THE MERIDIAN RESOURCE CORPORATION
QUARTERLY REPORT ON FORM 10-Q
INDEX
PAGE
NUMBER
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Operations (unaudited) for the
Three Months and Six Months Ended June 30, 1999
and 1998......................................................3
Consolidated Balance Sheets (unaudited) as of June 30, 1999
and December 31, 1998.........................................4
Consolidated Statements of Cash Flows (unaudited) for the
Six Months Ended June 30, 1999 and 1998.......................6
Notes to Consolidated Financial Statements (unaudited)...........7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations..........................12
Item 3. Quantitative and Qualitative Disclosures about Market Risk......22
PART II - OTHER INFORMATION
Item 1. Legal Proceedings...............................................24
Item 2. Changes in Securities and Use of Proceeds.......................25
Item 4. Submission of Matters to a Vote of Security Holders.............26
Item 6. Exhibits and Reports on Form 8-K................................26
SIGNATURE...................................................................28
2
<PAGE>
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
THREE MONTHS SIX MONTHS
ENDED JUNE 30 ENDED JUNE 30,
--------------------- ---------------------
1999 1998 1999 1998
--------- --------- --------- ---------
(IN THOUSANDS, EXCEPT FOR PER SHARE
INFORMATION)
REVENUES:
Oil and natural gas .......... $ 30,805 $ 11,508 $ 53,909 $ 23,274
Interest and other ........... 164 234 366 365
--------- --------- --------- ---------
30,969 11,742 54,275 23,639
--------- --------- --------- ---------
COSTS AND EXPENSES:
Oil and natural gas operating 4,046 1,808 8,216 3,326
Severance and ad valorem taxes 2,742 375 4,981 835
Depletion and depreciation ... 12,728 6,280 25,415 12,539
General and administrative ... 3,110 2,139 5,904 4,116
Interest ..................... 5,553 2,692 10,608 5,023
Impairment of long-lived assets -- 155,848 -- 196,126
--------- --------- --------- ---------
28,179 169,142 55,124 221,965
--------- --------- --------- ---------
INCOME (LOSS) BEFORE
INCOME TAXES ................. 2,790 (157,400) (849) (198,326)
INCOME TAX BENEFIT ............. -- (22,000) -- (22,000)
--------- --------- --------- ---------
NET INCOME (LOSS) .............. 2,790 (135,400) (849) (176,326)
--------- --------- --------- ---------
DIVIDEND REQUIREMENT ON
PREFERRED STOCK .............. (1,350) -- (2,700) --
--------- --------- --------- ---------
NET INCOME (LOSS) APPLICABLE
TO COMMON STOCKHOLDERS ....... $ 1,440 ($135,400) ($ 3,549) ($176,326)
========= ========= ========= =========
NET INCOME (LOSS) PER SHARE:
Basic ........................ $ 0.03 ($ 4.01) ($ .08) ($ 5.24)
========= ========= ========= =========
Diluted ...................... $ 0.03 ($ 4.01) ($ .08) ($ 5.24)
========= ========= ========= =========
See notes to consolidated financial statements.
3
<PAGE>
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(unaudited)
JUNE 30, DECEMBER 31,
1999 1998
--------- -------------
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ........................ $ 16,886 $ 9,478
Accounts receivable .............................. 26,167 32,558
Due from affiliates .............................. 1,690 4,848
Prepaid expenses and other ....................... 3,678 1,394
--------- -------------
Total current assets ........................... 48,421 48,278
--------- -------------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method
(including $82,836,000 [1999] and
$94,077,000 [1998] not subject to depletion) ... 865,714 820,322
Land ............................................. 478 478
Equipment ........................................ 7,328 6,775
--------- -------------
873,520 827,575
Accumulated depletion and depreciation ........... (461,548) (436,120)
--------- -------------
411,972 391,455
--------- -------------
OTHER ASSETS ....................................... 5,774 5,442
--------- -------------
$ 466,167 $ 445,175
========= =============
See notes to consolidated financial statements.
4
<PAGE>
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(unaudited)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
--------- -------------
<S> <C> <C>
(IN THOUSANDS)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable ....................................... $ 26,588 $ 19,138
Revenues and royalties payable ......................... 5,100 6,500
Accrued liabilities .................................... 16,337 24,440
Notes payable .......................................... 656 --
Current maturities of long-term debt ................... -- 84
--------- -------------
Total current liabilities ............................ 48,681 50,162
--------- -------------
LONG-TERM DEBT ........................................... 245,000 240,000
--------- -------------
9 1/2% CONVERTIBLE SUBORDINATED NOTES .................... 20,000 --
--------- -------------
LITIGATION LIABILITIES ................................... 6,205 6,205
--------- -------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value (25,000,000 shares
authorized, 3,982,906 [1999]
and 3,982,906 [1998] shares of Series A Cumulative
Convertible Preferred Stock issued at stated value) .. 135,000 135,000
Common stock, $0.01 par value (200,000,000 shares
authorized, 45,903,550 [1999] and
45,817,319 [1998] issued) ............................ 465 461
Additional paid-in capital ............................. 271,583 270,477
Accumulated deficit .................................... (260,396) (256,814)
Unamortized deferred compensation ...................... (371) (293)
--------- -------------
146,281 148,831
Treasury stock, at cost (0 [1999] and
1,275 [1998] shares) ................................... -- (23)
--------- -------------
Total stockholders' equit ............................... 146,281 148,808
--------- -------------
$ 466,167 $ 445,175
========= =============
</TABLE>
See notes to consolidated financial statements.
5
<PAGE>
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
SIX MONTHS ENDED JUNE 30,
1999 1998
----------- ----------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss ............................................. ($ 849) ($ 176,326)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion and depreciation ......................... 25,415 12,539
Amortization of other assets ....................... 609 58
Non-cash compensation .............................. 829 964
Impairment of long-lived assets .................... -- 196,126
Deferred income taxes .............................. -- (22,000)
Changes in assets and liabilities excluding effects of
acquisition of oil and gas properties:
Accounts receivable ................................ 6,391 (4,881)
Due from affiliates ................................ 3,158 (1,197)
Accounts payable ................................... 7,450 25,733
Revenues and royalties payable ..................... (1,400) (1,560)
Notes payable ...................................... 656 --
Accrued liabilities and other ...................... (1,334) (5,596)
----------- ----------
Net cash provided by operating activities ............ 40,924 23,860
----------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties and other ...... (59,822) (65,746)
Acquisition of oil and gas properties .............. (5,860) (37,078)
Sales of oil and gas properties .................... 9,546 2,100
----------- ----------
Net cash used in investing activities ................ (56,136) (100,724)
----------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt ....................... 35,000 74,896
Reductions in long-term debt ....................... (10,084) (58)
Proceeds from issuance of common stock ............. 1,132 1,292
Preferred stock dividends accrued .................. (2,700) --
Deferred loan costs ................................ (728) (1,452)
----------- ----------
Net cash provided by financing activities ............ 22,620 74,678
----------- ----------
NET CHANGE IN CASH AND CASH EQUIVALENTS .............. 7,408 (2,186)
CASH AND CASH EQUIVALENTS
AT BEGINNING OF PERIOD ............................. 9,478 8,083
----------- ----------
CASH AND CASH EQUIVALENTS
AT END OF PERIOD ................................... $ 16,886 $ 5,897
=========== ==========
See notes to consolidated financial statements.
6
<PAGE>
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. BASIS OF PRESENTATION
The consolidated financial statements reflect the accounts of The Meridian
Resource Corporation and its subsidiaries (the "Company") after elimination of
all significant intercompany transactions and balances. The financial statements
should be read in conjunction with the consolidated financial statements and
notes thereto included in the Company's Annual Report on Form 10-K for the year
ended December 31, 1998 as filed with the Securities and Exchange Commission.
The financial statements included herein as of June 30, 1999, and for the three
and six month periods ended June 30, 1999 and 1998 are unaudited, and, in the
opinion of management, the information furnished reflects all material
adjustments, consisting of normal recurring adjustments, necessary for a fair
statement of the results for the interim periods presented.
2. IMPAIRMENT OF LONG-LIVED ASSETS
No impairment of long-lived assets was recognized during the first six months of
1999 due to improved commodity prices and significant reserve additions made
during the period. During the first six months of 1998, the Company recognized
$196.1 million in non-cash write-downs of its oil and natural gas properties
under the full cost method of accounting, primarily as a result of declines in
both oil and natural gas prices which significantly lowered the present value of
proved oil and natural gas reserves as of June 30, 1998 and nonproductive
investments in oil and gas properties.
3. LONG-TERM DEBT
In May 1998, the Company amended and restated its credit facility with The Chase
Manhattan Bank as Administrative Agent (the "Credit Facility") to provide for
maximum borrowings, subject to borrowing base limitations, of up to $250
million. In November 1998, the Company amended the Credit Facility to increase
the then-existing borrowing base from $200 million to $250 million. The
borrowing base, currently set at $250 million, is scheduled to be redetermined
on August 23, 1999. In addition to the regularly scheduled semi-annual borrowing
base redeterminations, the lenders under the Credit Facility have the right to
redetermine the borrowing base at any time once during each calendar year and
the Company has the right to obtain a redetermination by the banks of the
borrowing base once during each calendar year. Borrowings under the Credit
Facility are secured by pledges of the outstanding capital stock of the
Company's material subsidiaries and a mortgage of all of the Company's offshore
oil and natural gas properties and several onshore oil and natural gas
properties. The Credit Facility contains various restrictive covenants,
including, among other things, maintenance of certain financial ratios and
restrictions on cash dividends on the Common Stock.
Borrowings under the Credit Facility mature on May 22, 2003.
Under the Credit Facility, as amended, the Company may secure either (i) an
alternative base rate
7
<PAGE>
loan that bears interest at a rate per annum equal to the greater of the
administrative agent's prime rate, a certificate of deposit based rate or a
federal funds based rate plus 0% to 1.5%; or (ii) a Eurodollar base rate loan
that bears interest, generally, at a rate per annum equal to the London
interbank offered rate plus 1.0% to 2.5%, depending on the Company's ratio of
the aggregate outstanding loans and letters of credit to the borrowing base. The
Credit Facility also provides for commitment fees ranging from .3% to .5% per
annum. At June 30, 1999, the Company had outstanding borrowings of $245 million
under the Credit Facility.
4. 9 1/2% CONVERTIBLE SUBORDINATED NOTES
During June 1999, the Company completed private placements of an aggregate of
$20 million of its 9 1/2% convertible subordinated notes due June 18, 2005 (the
"Notes"). The Notes are unsecured and contain customary events of default, but
do not contain any maintenance or other restrictive covenants. Interest is
payable on a quarterly basis.
The Notes are convertible at any time by the holders of the Notes into shares of
the Company's common stock, $.01 par value ("Common Stock"), utilizing a
conversion price of $7.00 per share (the "Conversion Price"). The Conversion
Price is subject to customary anti-dilution provisions. The holders of the Notes
have been granted registration rights with respect to the shares of Common Stock
that are issued upon conversion of the Notes or issuance of the warrants
discussed below.
The Notes may be prepaid by the Company at any time without penalty or premium;
however, in the event the Company redeems or prepays the Notes on or before June
21, 2001, the Company will issue to the holders of the Notes warrants to
purchase that number of shares of Common Stock into which such Notes would have
been convertible on the date of prepayment. Such warrants will have exercise
prices equal to the Conversion Price in effect on the date of issuance and will
expire on June 21, 2001, regardless of the date such warrants are issued.
5. COMMITMENTS AND CONTINGENCIES
LITIGATION
In November 1998, Enron Capital & Trade Resources Corp. ("Enron") filed an
action in the District Court of Harris County, Texas, 11th Judicial District,
Texas against the Company and certain Shell affiliates alleging causes of action
against the Company and Shell for trespass and tortious interference with
contract and seeking declaratory and injunctive relief. Enron asserts that the
Company's drilling and operation of certain Louisiana oil and gas wells has and
will trespass upon Enron's Louisiana property interests and tortiously interfere
with a Participation Agreement dated June 12, 1996 between Enron and Shell (the
"Participation Agreement"). Enron asserts further that it is being denied its
right to participate in certain drilling projects allegedly included under the
Participation Agreement, including interests in wells drilled in the Weeks
Island Field. In response to Enron's claims, the Company filed an action against
Enron in the 31st Judicial District for the Parish of Jefferson Davis, Louisiana
seeking injunctive relief against Enron for interfering with the Company's
rights to operate and asserting that the matter should be addressed and resolved
by the Louisiana Commissioner of Conservation. The Company subsequently entered
into a stipulation with Enron whereby Enron agreed not to contest the Company on
three wells drilled, in the Thornwell Field, two of which are currently
producing.
8
<PAGE>
The properties covered by the Participation Agreement are owned by the Company,
with record title in the Company's subsidiary, Louisiana Onshore Properties
Inc., which was acquired from Shell in the Shell Transactions. Subject to
certain agreed upon limitations, Enron, Shell and the Company have consented to
submit this dispute to arbitration. Enron has appointed an arbitrator and Shell
and the Company have together appointed a second arbitrator, and a third
arbitrator has been selected by Enron on one hand and Shell and the Company on
the other hand.
The Company is vigorously defending against Enron's claims and has reserved all
of its rights for reimbursement against Shell if Enron's claims are successful.
The Company believes that it is entitled to operate the referenced Louisiana
properties and that Enron is not entitled to any of the Company's interest in
wells that have been drilled in the Weeks Island Field. However, in the event of
an adverse determination resulting in a monetary judgment or property losses as
a result of Enron's claims with respect to the Weeks Island Field, the Company
believes that it is entitled to indemnification or reimbursement from Shell
under the agreements governing the Shell Transactions and have other rights and
actions under common law and state and federal securities laws, and in this
regard, the Company has filed suit against Shell to preserve these claims. The
Company has agreed to release Shell and its affiliates from any claims against
Shell that it may have with respect to the Weeks Island Field in exchange for
Shell's complete and unequivocal indemnity to the Company for any award,
judgement, declaration of title or settlement by Enron resulting from Enron's
claims relating to all wells and reserves located in the Weeks Island Field. as
a result of Shell's indemnity agreement, the Company currently does not believe
the dispute with Enron will have a material adverse effect on its financial
condition or results of operations.
9
<PAGE>
6. NET INCOME PER SHARE
The following tables set forth the computation of basic and diluted net income
(loss) per share:
<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30,
---------------------------------
1999 1998
--------------- ---------------
<S> <C> <C>
(IN THOUSANDS, EXCEPT PER SHARE)
Numerator:
Net income (loss) ................................. $ 2,790 ($ 135,400)
Less: Preferred dividend requirement .............. (1,350) --
--------------- ---------------
Net income (loss) used in per share calculation ... $ 1,440 ($ 135,400)
Denominator:
Denominator for basic net income (loss) per
share - weighted-average shares outstanding ..... 45,862 33,801
Effect of potentially dilutive common shares:
Employee and director stock options ............... 893 N/A
Warrants .......................................... 1,562 N/A
--------------- ---------------
Denominator for diluted net income (loss) per
share - weighted average shares outstanding
and assumed conversions ......................... 48,323 33,801
=============== ===============
Basic net income (loss) per share ................... $ .03 ($ 4.01)
=============== ===============
Diluted net income (loss) per share ................. $ .03 ($ 4.01)
=============== ===============
</TABLE>
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
---------------------------------
1999 1998
--------------- ---------------
(IN THOUSANDS, EXCEPT PER SHARE)
<S> <C> <C>
Numerator:
Net income (loss) ................................... ($ 849) ($ 176,326)
Less: Preferred dividend requirement ................ (2,700) --
--------------- ---------------
Net income (loss) used in per share calculation ..... ($ 3,549) ($ 176,326)
Denominator:
Denominator for basic net income (loss) per
share - weighted-average shares outstanding ....... 45,839 33,627
Effect of potentially dilutive common shares:
Employee and director stock options ................. N/A N/A
Warrants ............................................ N/A N/A
Denominator for diluted net income (loss) per
share - weighted average shares outstanding
and assumed conversions ........................... 45,839 33,627
=============== ===============
Basic net income (loss) per share ..................... ($ .08) ($ 5.24)
=============== ===============
Diluted net income (loss) per share ................... ($ .08) ($ 5.24)
=============== ===============
</TABLE>
10
<PAGE>
7. RELATED PARTY TRANSACTIONS
Texas Oil Distribution and Development, Inc. ("TODD") and Sydson Energy, Inc.
("Sydson"), entities controlled by Joseph A. Reeves, Jr. and Michael J. Mayell,
respectively, have each invested 1.5% in all wells in which the Company has
participated. In conjunction with obligations of TODD and Sydson related to
these working interests, the Board of Directors has authorized the acquisition
of interests held by TODD, Sydson and Messrs. Reeves and Mayell in the Chocolate
Bayou, Backridge and Kings Bayou fields on the basis of the Company's externally
prepared reserve report. The acquisitions of Chocolate Bayou and Backridge
interest were effective June 30, 1999 and the Kings Bayou interest acquisition
was effective July 15, 1999. Proceeds of $1.9 million to each of TODD and Sydson
and $1.3 million to each of Messrs. Reeves and Mayell due from the acquisition
are to be applied directly to current and/or future costs and expenses related
to TODD and Sydson's working interest rather than paid in cash.
11
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
The following is a discussion of the Company's financial operations for the six
months ended June 30, 1999 and 1998. The notes to the Company's consolidated
financial statements included in this report, as well as the Company's Annual
Report on Form 10-K for the year ended December 31, 1998 (and the notes attached
thereto), should be read in conjunction with this discussion.
GENERAL
SHELL TRANSACTIONS. On June 30, 1998, we acquired (the "LOPI Transaction")
Louisiana Onshore Properties Inc. ("LOPI"), an indirect subsidiary of Shell Oil
Company ("Shell"), pursuant to a merger of a wholly-owned subsidiary with LOPI.
The consideration paid in the LOPI Transaction consisted of 12,082,030 shares of
our common stock, $.01 par value ("Common Stock"), and a new issue of
convertible preferred stock (the "Preferred Stock") that is convertible into
12,837,428 shares of Common Stock, which together provided Shell Louisiana
Onshore Properties Inc., an indirect subsidiary of Shell ("SLOPI"), with
beneficial ownership of 39.9% of our common stock on a fully-diluted basis,
assuming the exercise of all outstanding stock options and warrants and the
conversion of all preferred stock. In a transaction separate from the LOPI
Transaction, we also acquired on June 30, 1998 from Shell Western E&P Inc., an
indirect subsidiary of Shell ("SWEPI"), various oil and gas property interests
located onshore in south Louisiana for a total cash consideration of $34.1
million after purchase price adjustments on both transactions (the "SWEPI
Acquisition").
The LOPI Transaction and the SWEPI Acquisition (together, the "Shell
Transactions") were effected to increase our reserves, lease acreage positions
and exploration prospects in Louisiana and are expected to substantially
increase our production and cash flow. The Shell Transactions were accounted for
utilizing the purchase method of accounting. Therefore, operations relating to
the oil and gas properties acquired in the Shell Transactions (the "Shell
Properties") are included in our results of operations beginning with the third
quarter of 1998.
INDUSTRY CONDITIONS. Our revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for oil and natural gas. Oil and
natural gas prices have been extremely volatile in recent years and are affected
by many factors outside of our control. In this regard, our average oil and
natural gas prices, which decreased substantially throughout 1998 and into the
first quarter of 1999, reflected an increase during the second quarter of 1999.
Our average oil price for the three months ended June 30, 1999 was $15.87 per
barrel compared to $11.44 per barrel for the three months ended March 31, 1999
and $12.86 per barrel for the three months ended June 30, 1998. Our average oil
price for the six months ended June 30, 1999 was $13.73 per barrel compared to
$13.33 per barrel for the six months ended June 30, 1998. Our average natural
gas price for the three months ended June 30, 1999 was $2.28 per MCF compared to
$1.83 per MCF for the three months ended March 31, 1999 and $2.34 for the three
months ended June 30, 1998. Our average natural gas price for the six months
ended June 30, 1999 was $2.04 per MCF compared to $2.32 per MCF for the six
months ended June 30, 1998. Any significant reduction in prices we received for
our oil and gas production over levels experienced during the second quarter of
1998 could result in decreased cash flow received from our producing properties,
and a delay in the timing of exploration activities, which will adversely affect
our revenues, profitability and our ability to maintain or increase our
exploration and development program.
12
<PAGE>
RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 1999 COMPARED TO THREE MONTHS ENDED JUNE 30, 1998
OPERATING REVENUES. Second quarter 1999 oil and natural gas revenues increased
$19.3 million as compared to second quarter 1998 revenues primarily due to
production volumes increasing 147% and average commodity prices increasing 8%
both on a natural gas equivalent basis. The production increase is a direct
result of the inclusion of results from the Shell Properties, as well as new
wells being placed on production during the last twelve months.
The following table summarizes our operating revenues, production volumes and
average sales prices for the three months ended June 30, 1999 and 1998.
THREE MONTHS ENDED 1999
JUNE 30, 1999 PERCENTAGE
---------------------- INCREASE INCREASE
1999 1998 (DECREASE) (DECREASE)
---------- ---------- ---------- ----------
Production Volumes:
Oil (Mbbl) ................ 1,120 244 876 359%
Natural gas (Mmcf) ........ 5,728 3,573 2,155 60%
MMCFE ..................... 12,448 5,037 7,411 147%
Average Sales Prices:
Oil (Bbl) ................. $ 15.87 $ 12.72 $ 3.15 25%
Natural gas (Mcf) ......... $ 2.28 $ 2.34 $ (0.06) (3%)
MMCFE ..................... $ 2.47 $ 2.28 $ 0.19 8%
Gross Revenues (000's):
Oil ....................... $ 17,771 $ 3,104 $ 14,667 473%
Natural gas ............... 13,034 8,370 4,664 56%
Pipeline .................. -- 34 (34) (100%)
---------- ---------- ----------
Total Operating ......... $ 30,805 $ 11,508 $ 19,297 168%
========== ========== ==========
OPERATING EXPENSES. Oil and natural gas operating expenses increased $2.2
million to $4.0 million for the three months ended June 30, 1999, compared to
$1.8 million for the same period in 1998. This increase was primarily due to the
inclusion of costs and expenses from the Shell Properties, as well as new wells
brought on production in the last twelve months. On an MCFE basis, operating
expenses have decreased in the three months ended June 30, 1999 to $.33 from
$.36 for the three months ended June 30, 1998. Operating costs on a MCFE basis
have decreased to $.33 in the second quarter of 1999, from $.34 in the first
quarter of 1999 and from $.39 during the second half of 1998. These decreases
are primarily the result of the program that we implemented to reduce the
operating costs associated with the Shell Properties.
13
<PAGE>
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $2.4
million to $2.7 million for the second quarter of 1999, compared to $0.4 million
during the same period in 1998. This increase is largely attributable to the
additional production resulting from the purchase of the Shell Properties, all
of which are subject to state severance taxes and parish ad valorem taxes.
INTEREST AND OTHER INCOME. Interest and other income during the second quarter
of 1999 increased $.2 million from the comparable period in 1998 reflecting
larger cash balances associated with our operating more properties.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased during
the second quarter of 1999 to $12.7 million from $6.3 million for the same
period of 1998. This increase was primarily a result of the 136% increase in
production on an MCFE basis over the comparable period in 1998. Although
depletion and depreciation expense increased in the aggregate, on an MCFE basis
there was a decrease of $.23 per MCFE to $1.02 per MCFE for the quarter ended
June 30, 1999 from $1.25 per MCFE during the comparable time period in 1998.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
$1.0 million to $3.1 million for three months ended June 30, 1999 compared to
$2.1 million during the comparable period last year. This increase was primarily
a result of increases in salaries and wages and related employee costs
associated with our expanded exploration and production activities resulting
from our acquisition of the Shell Properties. On a unit of production basis,
general and administrative expense has decreased 40% to $.25 per MCFE for the
three months ended June 30, 1999 from $.42 per MCFE during the comparable period
of 1998.
INTEREST EXPENSE. Interest expense increased $2.9 million to $5.6 million during
the second quarter of 1999 compared to $2.7 million in the comparable period in
1998. The increase is a result of borrowings of approximately $37 million under
our credit facility utilized to fund the purchase of certain properties in the
Shell Transaction and continued borrowings to fund our exploration and
development program during the last half of 1998 and into 1999.
IMPAIRMENT OF LONG-LIVED ASSETS. Due to the improvement in commodity prices and
significant reserve additions during the first six months of 1999, it was not
necessary to record an impairment of long-lived assets during the second quarter
of 1999. The second quarter of 1998 reflected a pre-tax charge of $155.8 million
as an impairment of long-lived assets due to prevailing market conditions at
June 30, 1998.
SIX MONTHS ENDED JUNE 30, 1999 COMPARED TO SIX MONTHS ENDED JUNE 30, 1998
OPERATING REVENUES. Oil and natural gas revenues during the six months ended
June 30, 1999, increased $30.6 million as compared to revenues during the six
months ended June 30, 1998, due to production volumes increasing by 144% on a
natural gas equivalent basis. This production increase was a direct result of
the inclusion of results from the Shell Properties, as well as new wells being
placed on production during the last twelve months. Oil and natural gas prices,
on a natural gas equivalent basis, decreased 5% during the first six months of
1999 compared to the same period in 1998.
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The following table summarizes production volumes, average sales prices and
gross revenues for the six months ended June 30, 1999 and 1998.
1999
SIX MONTHS ENDED 1999 PERCENTAGE
JUNE 30, INCREASE INCREASE
1999 1998 (DECREASE) (DECREASE)
--------- --------- ---------- ----------
Production Volumes:
Oil (Mbbl) .................... 2,164 454 1,710 377%
Natural gas (Mmcf) ............ 11,837 7,431 4,406 59%
MMCFE ......................... 24,821 10,155 14,666 144%
Average Sales Prices:
Oil (Bbl) ..................... $ 13.73 $ 13.15 $ 0.58 4%
Natural gas (Mcf) ............. $ 2.04 $ 2.32 ($ 0.28) (12%)
MMCFE ......................... $ 2.17 $ 2.29 ($ 0.12) (5%)
Gross Revenues (000's):
Oil ........................... $ 29,714 $ 5,971 $ 23,743 398%
Natural gas ................... 24,195 17,220 6,975 40%
Pipeline ...................... -- 83 (83) (100%)
--------- --------- ----------
Total ......................... $ 53,909 $ 23,274 $ 30,635 132%
========= ========= ==========
OPERATING EXPENSES. Oil and natural gas operating expenses increased $4.9
million to $8.2 million for the six months ended June 30, 1999, compared to $3.3
million for the six months ended June 30, 1998. This increase was primarily due
to added operating expenses related to the inclusion of costs and expenses from
the Shell Properties as well as new wells brought on production in the last
twelve months. On a MCFE basis, operating expenses were $.33 per MCFE for the
first half of 1999 compared to $.33 per MCFE for the comparable period last
year. Compared to the second half of 1998, which included production and
operating expenses from the Shell Properties, operating costs declined $.06 per
MCFE from $.39 per MCFE during the second half of 1999. This reduction reflects
the results of the program that we implemented to reduce the operating costs
associated with the Shell Properties.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased $4.2
million to $5.0 million for the six months ended June 30, 1999, compared to $0.8
million for the six months ended June 30, 1998. This increase is largely
attributable to the additional production from the purchase of the Shell
Properties, all of which are subject to state severance tax and parish ad
valorem tax.
INTEREST AND OTHER INCOME. Interest and other income remained constant at $.4
million for each of the six month periods ended June 30, 1999 and 1998.
DEPLETION AND DEPRECIATION. Depletion and depreciation expense increased $12.9
million to $25.4 million during the first six months of 1999 from $12.5 from the
same period last year. This increase was primarily a result of the 144% increase
in production on an MCFE basis over the comparable
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period in 1998. Although depletion and depreciation expense increased in the
aggregate, on an MCFE basis there was a decrease of $.21 per MCFE to $1.02 per
MCFE for the six months ended June 30, 1999 from $1.23 per MCFE during the first
half of 1998.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
$1.8 million to $5.9 million for the first six months of 1999 compared to $4.1
million during the first six months of 1998. This increase was primarily a
result of increases in salaries and wages and related employee costs associated
with our expanded exploration and production activities resulting from our
acquisition of the Shell Properties. General and administrative expense, on a
unit of production basis, has decreased 41% to $.24 per MCFE for the six months
ended June 30, 1999 from $.41 per MCFE during the comparable period or 1998.
INTEREST EXPENSE. Interest expense increased $5.6 million to $10.6 million
during the first six months of 1999 compared to $5.0 million during the
comparable period of 1998. The increase is a result of borrowings of
approximately $37 million under our credit facility to fund the purchase of
certain properties in the Shell Transaction and continued borrowing to fund our
exploration and development programs during the last half of 1998 and into 1999.
IMPAIRMENT OF LONG-LIVED ASSETS. We follow the full cost method of accounting
for our investments in oil and natural gas properties, which requires that the
net carrying value of oil and natural gas properties is limited to the sum of
the present value (10% discount rate) of the estimated future net cash flows
from proved reserves, based on the current prices and costs, plus the lower of
cost or estimated value of unproved properties. We did not record an impairment
of long-lived assets during the first six months of 1999 since there were
significant reserve additions during the period as well as improved commodity
prices during the second quarter of 1999. During the first six months of 1998,
we recognized $196.1 million in non-cash write-downs of our oil and natural gas
properties under the full cost method of accounting.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the second quarter of 1999, the Company's liquidity
needs were met from cash from operations, borrowings under our credit facility
and the issuance of $20 million of 9 1/2% convertible subordinated notes (the
"Notes"). As of June 30, 1999, the Company had a cash balance of $16.9 million
and a working capital deficit of $0.3 million. The increase in the cash balance
and the reduction in working capital deficit from levels existing at March 31,
1999, reflects the proceeds from the issuance of the Notes, partially offset by
a $5 million repayment of borrowings under our credit facility, which remains
available to the Company, and capital expenditures related to our increasing
exploration and development activities.
AMENDED CREDIT FACILITY. In May 1998, we amended and restated our credit
facility with The Chase Manhattan Bank as Administrative Agent (the "Credit
Facility") to provide for maximum borrowings, subject to borrowing base
limitations, of up to $250 million. In November 1998, we amended the Credit
Facility to increase the then-existing borrowing base from $200 million to $250
million. The borrowing base was reaffirmed on March 31, 1999 and is currently
set at $250 million, with a scheduled redetermination on August 23, 1999.
Although we have not received any binding commitments from our lenders, we
believe there will be no negative redetermination of our borrowing base at
August 23, 1999 due to the significant increases in production and reserves
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we have achieved during the first six months of 1999. In addition to regularly
scheduled semi-annual borrowing base redeterminations, the lenders under the
Credit Facility have the right to redetermine the borrowing base at any time
once during each calendar year and we have the right to obtain a redetermination
by the banks of the borrowing base once during each calendar year. Borrowings
under the Credit Facility are secured by pledges of the outstanding capital
stock of our material subsidiaries and a mortgage of all of our offshore oil and
natural gas properties and several onshore oil and natural gas properties.
Borrowings under the Credit Facility mature on May 22, 2003.
The Credit Facility includes various restrictive covenants including an interest
coverage ratio of 3.0 to 1.0, a minimum net worth requirement of approximately
$82 million, and a total debt leverage ratio (based upon total indebtedness to
12-month trailing pro forma EDITDA) of 4.00 to 1.00 at June 30, 1999, 3.50 to
1.00 at September 30, 1999 and 3.25 to 1.00 at December 31, 1999 and thereafter.
Under the Credit Facility, we also were required to have a daily average
production of 150 Mmcfe/d during the month of June 1999 which we were unable to
comply with primarily due to the forced shut-in of the C.M. Thibodaux #1 well
discussed below. We have obtained a waiver from our lenders in this regard.
Assuming that we continue to be successful in our development and exploration
program during the next 12 months, management believes that we will be able to
comply with our Credit Facility covenants primarily due to the increase in
production scheduled to begin in the near-term at two of our most recent
discoveries in addition to the positive effects of higher oil and gas prices;
however, any declines in oil and gas commodity prices or unanticipated declines
or delays in production may adversely affect our ability to comply with our
Credit Facility covenants.
Under the Credit Facility, as amended, we may secure either (i) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate, a certificate of deposit based rate or a
federal funds based rate plus 0% to 1.5% or (ii) a Eurodollar base rate loan
that bears interest, generally, at a rate per annum equal to the London
interbank offered rate plus 1.0% to 2.5%, depending on the ratio of the
aggregate outstanding loans and letters of credit to the borrowing base. The
Credit Facility also provides for commitment fees ranging from .3% to .5% per
annum.
9 1/2% CONVERTIBLE SUBORDINATED NOTES. During June 1999, we completed private
placements of an aggregate of $20 million of its 9 2% convertible subordinated
notes due June 18, 2005 (the "Notes"). The Notes are unsecured and contain
customary events of default, but do not contain any maintenance or other
restrictive covenants. Interest is payable on a quarterly basis.
The Notes are convertible at any time by the holders of the Notes into shares of
our common stock, $.01 par value ("Common Stock"), utilizing a conversion price
of $7.00 per share (the "Conversion Price"). The Conversion Price is subject to
customary anti-dilution provisions. The holders of the Notes have been granted
registration rights with respect to the shares of Common Stock that are issued
upon conversion of the Notes or issuance of the warrants discussed below.
The Notes may be prepaid by us at any time without penalty or premium; however,
in the event we redeem or prepay the Notes on or before June 21, 2001, we will
issue to the holders of the Notes warrants to purchase that number of shares of
Common Stock into which such Notes would have been convertible on the date of
prepayment. Such warrants will have exercise prices equal to the
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Conversion Price in effect on the date of issuance and will expire on June 21,
2001, regardless of the date such warrants are issued.
CAPITAL EXPENDITURES. Capital expenditures, less the reinvestment of proceeds
from the sale of properties during the six months ended June 30, 1999, consisted
of $45.4 million for property and equipment additions related to exploration and
development of various prospects (including leases), seismic data acquisitions,
and drilling and completion costs. We currently expect capital expenditures for
the remainder of 1999 to be approximately $30.0 million and we anticipate that
such capital expenditures will be funded from cash flows from our producing
properties, borrowings under the Credit Facility and remaining proceeds from
sale of Notes. We expect our capital budget for the remainder of 1999 to focus
on lower risk development projects, concentrating on our Weeks Island, North
Turtle Bayou/Ramos and Thornwell projects. Availability of capital to fund the
remainder of our 1999 exploration and development program will depend upon the
success of our drilling program and the nature and extent of capital
expenditures required for development of discoveries. In this regard, we
anticipate that based on our current product price and production forecast,
internal cash flow and borrowings under the Credit Facility and the remaining
proceeds from sale of Notes should fully fund the remainder of our 1999 capital
expenditure program. The level of capital expenditures for our 2000 exploration
and development program has not been finally determined and will depend upon a
variety of factors, including prevailing prices for oil and gas and our
expectations as to future pricing and the level of cash flow from our
operations. We currently anticipate funding our 2000 exploration and development
program utilizing cash flow from operations, however, we will continue to review
our options to finance a portion of our future exploration programs with
additional third party debt or equity financing.
C. M. THIBODAUX NO. 2. During late June, the C. M. Thibodaux No. 2 well
experienced uncontrolled gas flows and a fire for a short period (8 days), which
has been capped with a diverting well head. The Company is proceeding with the
installation of a snubbing unit to complete the kill procedure and finalize
plugging of the well. A replacement and/or relief well to the C. M. Thibodaux
No. 2 well has reached a depth of 13,612 feet and the Company expects to reach
its total depth of 18,630 feet within the next 60 days. The Company currently
believes that it has adequate insurance coverage to minimize any economic losses
and other damages arising out of these events.
DIVIDENDS. It is our policy to retain our existing cash for reinvestment in our
business, and therefore, we do not anticipate that we will pay dividends with
respect to the Common Stock in the foreseeable future. The Preferred Stock
issued upon closing of the LOPI Transaction accrues an annual cash dividend of
4% of its stated value with the dividend ceasing to accrue incrementally on
one-third of the shares of Preferred Stock on June 30, 2001, 2002 and 2003 so
that no dividends will accrue on any shares of Preferred Stock after June 30,
2003. Dividends on the Preferred Stock aggregating $2.7 million were accrued for
the first six months in 1999.
STOCK RIGHTS AND RESTRICTIONS AGREEMENT. In light of the large ownership
position issued to SLOPI in the LOPI Transaction and in recognition of both our
and SLOPI's desire that the Company function as an independent oil and gas
company, we entered into a Stock Rights and Restrictions Agreement with SLOPI
that define and limit SLOPI's and our respective rights and obligations. These
agreements will limit SLOPI's and its affiliates' control while protecting their
interests in the context of certain extraordinary transactions by (i) allowing
SLOPI to maintain representation on our Board of Directors, (ii) restricting
SLOPI's and its affiliates' ability to effect certain business combinations with
us or to propose certain business
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combinations with us, (iii) restricting the ability of SLOPI and its affiliates
to sell certain portions of their shares of Common Stock and Preferred Stock,
subject to certain exceptions designed to permit them to sell such shares over
time and to sell such shares in the event of certain business combinations
involving us, (iv) limiting SLOPI's and its affiliates' discretionary voting
rights to 23% of the total voting shares, except with respect to certain
extraordinary events and in situations in which the price of the Common Stock
for a period of time has been less than $5.50 per share or we are in material
breach of our obligations under the agreements governing the LOPI Transaction,
(v) permitting SLOPI and its affiliates to purchase additional amounts of our
securities in order to maintain a 21% beneficial ownership interest in our
Common Stock or securities convertible into our Common Stock, (vi) extending
certain statutory and corporate restrictions on business combinations applicable
to SLOPI and its affiliates and (vii) obligating us, at our option, to issue a
currently indeterminable number of additional shares of Common Stock in the
future or pay cash in satisfaction of a make-whole provision contained in the
Stock Rights and Restrictions Agreement in the event SLOPI receives less than
approximately $10.52 per share on the sale of any Common Stock that is issuable
upon conversion of the Preferred Stock. SLOPI currently is restricted from
selling shares of Common Stock owned by it (including shares of common stock
issued to it upon conversion of the Preferred Stock) until July 1, 2000.
Beginning on July 1, 2000, SLOPI may sell 25% of the Common Stock owned by it
and may sell an incremental 25% of the Common Stock owned by it each year until
June 30, 2003, at which time it is free to sell all Common Stock owned by it.
Although SLOPI's ability to sell all of the Common Stock issued to it upon
conversion of the Preferred Stock is limited until July 1, 2003, in the event
SLOPI could sell all Common Stock issued on conversion of the Preferred Stock at
the market prices existing on August 5, 1999, our make-whole obligation would be
approximately $84.5 million, which we may satisfy at our option in cash or
Common Stock. This obligation could significantly dilute all holders of our
Common Stock other than Shell, or significantly reduce our ability to raise
additional funds for exploration and development.
YEAR 2000
We are currently conducting a company-wide Year 2000 readiness program ("Y2K
Program"). The Y2K Program is addressing the issue of computer programs and
embedded computer chips being unable to distinguish between the year 1900 and
the year 2000. Therefore, some computer hardware and software will need to be
modified prior to the year 2000 to remain functional. We believe that the
Company's internal accounting and operating systems are substantially Year 2000
compliant.
Our Y2K Program is divided into three major categories: (i) internal information
and accounting ("IT") systems, (ii) non-"IT" equipment and systems and (iii)
third-party suppliers and customers. The general stages of review with respect
to each of the categories are (a) identifying and assessing items or systems
that are not Year 2000 compliant, (b) assessing costs and expenses associated
with the various alternatives for remedying items and systems that are not Year
2000 compliant and (c) repairing or replacing items that are determined not to
be Year 2000 compliant.
We have completed our review of our IT equipment and systems and currently
believe that our internal information and accounting systems are Year 2000
compliant, except for certain field software that we currently do not believe
are material to our operations. We have currently tested an alternative solution
for making such field software Year 2000 compliant, and believe the costs
associated therewith will not be material.
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We currently are in the process of reviewing our non-IT equipment and systems.
We do not believe such equipment and systems will present any material Year 2000
issues. At present, we have not identified any non-IT equipment and systems that
are not Year 2000 compliant that cannot be remedied or replaced at minimal cost
to us.
We are in the process of assessing our third party Year 2000 issues during the
first and second quarter of 1999. Our third party review initially consists of
written inquiries to third party suppliers, subcontractors and customers
requesting information and representations from such third parties as to their
readiness for the Year 2000. We are in the process of circulating these
responses and, based upon such responses, will determine the necessity for
requesting additional information as appropriate. We expect our initial review
of third parties to be substantially complete during the third quarter of 1999.
We believe we have alternative suppliers and product customers to mitigate
material exposure if certain of our current suppliers and customers are
determined not to be Year 2000 ready.
Management believes that it has taken reasonable steps in developing its Y2K
Program. Notwithstanding these actions, there can be no assurance that all of
our Year 2000 issues or those of our key suppliers, subcontractors or customers
will be resolved or addressed satisfactorily before the Year 2000 commences. If
our key suppliers, subcontractors, customers and other third parties fail to
address their Year 2000 issues, and there are no alternatives available to us,
then our usual channels of supply and distribution could be disrupted, in which
event we could experience a material adverse impact on its business, results of
operations or financial position. In addition, although we believe our internal
planning efforts are adequate to address our internal Year 2000 concerns, there
can be no assurances that we will not experience unanticipated negative
consequences and material costs caused by undetected errors or defects in the
technology used in its internal systems, which could have material adverse
effect on our business, results of operations or financial condition. We
currently are unable to estimate the most reasonably likely worst-case effects
of the arrival of the year 2000 and currently do not have a contingency plan in
place for any such unanticipated negative effects. We intend to analyze
reasonably likely worst-case scenarios and the need for such contingency
planning once our review of third-party preparedness described above has been
completed, and we expect to complete this analysis by September 30, 1999.
It is anticipated that the total costs related to the Year 2000 issue will not
exceed $250,000. The majority of which will be incurred by us in 1999. To date,
there have been no material deferments of other IT projects resulting from the
work taking place on our Y2K Program.
FORWARD-LOOKING INFORMATION
From time-to-time, we may make certain statements that contain "forward-looking"
information as defined in the Private Securities Litigation Reform Act of 1995
and that involves risk and uncertainty. These forward-looking statements may
include, but are not limited to exploration and seismic acquisition plans,
anticipated results from current and future exploration prospects future capital
expenditure plans, anticipated results from third party disputes and litigation,
expectations regarding compliance with our credit facility, the anticipated
results of wells based on logging data and production tests, future sales of
production, earnings, margins, production levels and costs, market trends in the
oil and natural gas industry and the exploration and development sector thereof,
environmental and other expenditures and various business trends.
Forward-looking statements may
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be made by management orally or in writing including, but not limited to, the
Management's Discussion and Analysis of Financial Condition and Results of
Operations section and other sections of our filings with the Securities and
Exchange Commission under the Securities Act of 1933 and the Securities Exchange
Act of 1934.
Actual results and trends in the future may differ materially depending on a
variety of factors including, but not limited to the following:
CHANGES IN THE PRICE OF OIL AND NATURAL GAS. The price we receive for our oil
and natural gas production and the level of such production are subject to wide
fluctuations and depend on numerous factors that we do not control, including
seasonality, worldwide economic conditions, the condition of the United States
economy (particularly the manufacturing sector), foreign imports, political
conditions in other oil-producing and natural-gas-producing countries, the
actions of the Organization of Petroleum Exporting Countries and domestic
government regulation, legislation and policies. Material declines in the prices
we receive for oil and natural gas could make our actual results differ from
those reflected in our forward-looking statements.
OPERATING RISKS. The occurrence of a significant event for which we are not
fully insured against could have a material adverse effect on our financial
position and results of operations. Our operations are subject to all of the
risks normally incident to the exploration for and the production of oil and
natural gas, including uncontrollable flows of oil, natural gas, brine or well
fluids into the environment (including groundwater and shoreline contamination),
blowouts, cratering, mechanical difficulties, fires, explosions, unusual or
unexpected formation pressures, pollution and environmental hazards, and other
operating and productions risks such as title problems, weather conditions,
compliance with government permitting requirements, shortages of or delays in
obtaining equipment, reductions in product prices, limitations in the market for
products, litigation and disputes in the ordinary course of business, each of
which could result in damage to or destruction of oil and natural gas wells,
production facilities or other property, or injury to persons. Although we
maintain insurance coverage considered to be customary in the industry, we are
not fully insured against certain of these risks either because such insurance
is not available or because of high premium costs. We cannot predict if or when
any such risks could affect us. The occurrence of a significant event for which
we are not adequately insured could cause our actual results to differ from
those reflected in our forward-looking statements.
DRILLING RISKS. Our decision to purchase, explore, develop or otherwise exploit
a prospect or property will depend in part on the evaluation of data obtained
through geophysical and geological analysis, production data and engineering
studies, which are inherently imprecise. Therefore, we cannot assure you that
all of our drilling activities will be successful or that we will not drill
uneconomical wells. The occurrence of unexpected drilling results could cause
our actual results to differ from those reflected in our forward-looking
statements.
UNCERTAINTIES IN ESTIMATING RESERVES AND FUTURE NET CASH FLOWS. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of oil and natural gas that cannot be measured in an exact manner,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserve estimates are inherently imprecise and may be expected to change as
additional information becomes available. There are numerous uncertainties
inherent in estimating quantities and values
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of proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond our control. Because all
reserve estimates are to some degree speculative, the quantities of oil and
natural gas that we ultimately recover, production and operating costs, the
amount and timing of future development expenditures and future oil and natural
gas sales prices may differ from those assumed in these estimates. Significant
downward revisions to our existing reserve estimates could cause our actual
results to differ from those reflected in our forward-looking statements.
YEAR 2000. The risks related to the year 2000, and the dates on which we believe
our Y2K Program will be completed, are based on management's best estimates,
which were derived utilizing numerous assumptions of future events, including
the continued availability of certain resources, third-party modification plans
and other factors. However, there can be no guarantee that these estimates will
be achieved, or that there will not be a delay in, or increased costs associated
with, the implementation of our Y2K Program. Specific factors that might cause
differences between the estimates and actual results include, but are not
limited to, the availability and cost of personnel trained in these areas, the
ability to locate and correct all relevant computer codes, timely responses to
and corrections by third parties and suppliers, the ability to implement
interfaces between the new systems and the systems not being replaced, and
similar uncertainties. Due to the general uncertainty inherent in the Year 2000
problem, resulting in part from the uncertainty of the Year 2000 readiness of
third parties and the interconnection of global businesses, we cannot ensure our
ability to timely and cost effectively resolve problems associated with the Year
2000 issue that may affect our operations and business or expose us to
third-party liability.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are currently exposed to market risk from hedging contracts changes and
changes in interest rates. We have not previously utilized hedging contracts. A
discussion of our market risk exposure in financial instruments follows.
HEDGING CONTRACTS
Effective July 16, 1999, the Company entered into certain hedging contracts as
summarized in the table below. The Notional Amount is equal to the total net
volumetric hedge position of the Company during the periods. The positions
effectively hedge approximately 60% of the Company's current oil production. The
fair values of the hedge are based on the difference between the strike price
and the New York Mercantile Exchange future prices for the applicable trading
months of 1999 and 2000.
Weighted Average Fair Value at
Notional Strike Price June 30, 1999
Amount ($ per unit) (in thousands)
-------- ------------------- ---------------
Floor Ceiling
Oil (thousands of barrels): ------- ---------
July 1999 - June 2000............ 2,457 $16.00 $24.00 $ 0
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INTEREST RATES
We are subject to interest rate risk on our long-term fixed interest rate debt
and variable interest rate borrowings. Our long-term borrowings primarily
consist of borrowings under our Credit Facility and the $20 million principal of
9 1/2% Convertible Subordinated Notes due June 15, 2005. Since borrowings under
our Credit Facility float with prevailing interest rates (except for the
applicable interest period for Eurodollar loans), the carrying value of
borrowings under our Credit Facility should approximate the fair market value of
such debt. Changes in interest rates, however, will change our cost of
borrowing. Assuming $250 million remains borrowed under the Credit Facility, we
estimate our annual interest expense will increase by $2.5 million for each 100
basis point increase in the applicable interest rates utilized under our Credit
Facility. Changes in interest rates would, assuming all other things being
equal, cause the fair market value of debt with a fixed interest rate, such as
the Notes, to increase or decrease, and thus increase or decrease the amount
required to refinance the debt. The fair value of the Notes is dependent on
prevailing interest rates and our current stock price as it relates to the
conversion price of $7.00 per share of our Common Stock.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
C.M. THIBODAUX NO. 2
During late June 1999, the Company's C. M. Thibodaux No. 2 well experienced
uncontrolled gas flows and a fire for a short period (8 days), which has been
capped with a diverting well head. The Company is proceeding with the
installation of a snubbing unit to complete the kill procedure and finalize
plugging of the well. A replacement and/or relief well to the C. M. Thibodaux
No. 2 well has reached a depth of 13,612 feet and the Company expects to reach
its total depth of 18,630 feet within the next 60 days. Once the replacement
well is completed, the Company will be able to determine whether any material
reserves have been lost. A class action lawsuit has been filed in the 15th
Judicial District Court, Parish of St. Mary, Louisiana No. 104,204 "D", against
various of the Company's operating subsidiaries as well as other third parties
involved with the Company in drilling the well alleging various economic and
environmental damage was caused by the negligence of the Company's operating
subsidiaries and the other third party defendants. At this time, this lawsuit
has not been served on the Company's subsidiaries or any of the other third
party defendants. The Company does not believe that its actions were negligent
with respect to the operation of the C.M. Thibodaux No. 2 and intends to
vigorously defend this lawsuit if it is pursued by the plaintiffs. In the event
of an adverse determination, however, the Company believes that is has adequate
insurance coverage to minimize any economic losses and other damages arising out
of these events; and therefore, does not believe that these matters surrounding
the C.M. Thibodaux No. 2 will have a material adverse effect on its financial
condition or results of operation.
ENRON DISPUTE
In November 1998, Enron Capital & Trade Resources Corp. ("Enron") filed an
action in the District Court of Harris County, Texas, 11th Judicial District,
Texas against the Company and certain Shell affiliates alleging causes of action
against the Company and Shell for trespass and tortious interference with
contract and seeking declaratory and injunctive relief. Enron asserts that the
Company's drilling and operation of certain Louisiana oil and gas wells has and
will trespass upon Enron's Louisiana property interests and tortiously interfere
with a Participation Agreement dated June 12, 1996 between Enron and Shell (the
"Participation Agreement"). Enron asserts further that it is being denied its
right to participate in certain drilling projects allegedly included under the
Participation Agreement, including interests in wells drilled in the Weeks
Island Field. In response to Enron's claims, the Company filed an action against
Enron in the 31st Judicial District for the Parish of Jefferson Davis, Louisiana
seeking injunctive relief against Enron for interfering with the Company's
rights to operate and asserting that the matter should be addressed and resolved
by the Louisiana Commissioner of Conservation. The Company subsequently entered
into a stipulation with Enron whereby Enron agreed not to contest the Company on
three wells drilled in the Thornwell Field, two of which are currently
producing.
The properties covered by the Participation Agreement are owned by the Company,
with record title in the Company's subsidiary, Louisiana Onshore Properties
Inc., which was acquired from Shell in the Shell Transactions. Subject to
certain agreed upon limitations, Enron, Shell and the Company
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have consented to submit this dispute to arbitration. Enron has appointed an
arbitrator and Shell and the Company have together appointed a second
arbitrator. A third arbitrator has been appointed by Enron on one hand and Shell
and the Company on the other hand.
The Company is vigorously defending against Enron's claims and has reserved all
of its rights for reimbursement against Shell if Enron's claims are successful.
The Company believes that its is entitled to operate the referenced Louisiana
properties and that Enron is not entitled to any of the Company's interest in
wells that have been drilled in the Weeks Island Field. However, in the event of
an adverse determination resulting in a monetary judgment or property losses as
a result of Enron's claims with respect to the Weeks Island Field, the Company
believes that it is entitled to indemnification or reimbursement from Shell
under the agreements governing the Shell Transactions and have other rights and
actions under common law and state and federal securities laws, and in this
regard, the Company has filed suit against Shell to preserve these claims. The
Company has agreed to release Shell and its affiliates from any claims against
Shell that it may with respect to the Weeks Island Field in exchange for Shell's
complete and unequivocal indemnity to the Company for any award, judgement,
declaration of title or settlement by Enron resulting from Enron's claims
relating to all wells and reserves located in the Weeks Island Field. As a
result of Shell's indemnity agreement, the Company currently does not believe
the dispute with Enron will have a material adverse effect on its financial
condition or results of operations.
AMOCO LITIGATION
The Company previously filed an appeal relating to the decision of the federal
district court in the Amoco litigation that was previously described in the
Company's Annual Report on Form 10-K for the year ended December 31, 1998. In
connection with this appeal, the court entered a judgement aggregating against
all parties including the Company in the amount of $8.1 million. The Company is
in the process of applying for a rehearing and in the event such rehearing is
denied, the Company intends to appeal the decision. As previously reported, the
Company already has accrued $6.2 million relating to this dispute and does not
expect any additional accruals will be necessary.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
During June 1999, the Company issued in two separate private placements $20
million in principal amounts of 9 1/2% Convertible Subordinated Notes due June
18, 2005 (the "Notes"). The Notes were issued pursuant to an exemption from
registration under Section 4(2) of the Securities Act of 1933, as amended. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" for additional information regarding the Notes.
On May 5, 1999, the Board of Directors of The Meridian Resource Corporation (the
"Company") adopted a shareholder rights plan pursuant to which it declared a
dividend of one preferred share purchase right (a "Right") for each outstanding
share of common stock, par value $0.01 per share (the "Common Stock"), of the
Company and authorized the issuance of one Right for each share or Common Stock.
The dividend was payable on May 17, 1999 (the "Record Date") to the shareholders
of record on that date. The description and terms of the Rights are set forth in
a Rights Agreement (the "Rights Agreement") between the Company and American
Stock Transfer & Trust Company, as Rights Agent (the "Rights Agent") and are
summarized in the Company's Current Report on Form 8-K dated May 5, 1999.
25
<PAGE>
In connection with the declaration of the Rights dividend, the Company's Board
of Directors also amended the Company's Bylaws to provide for an advance notice
provision for shareholder proposals to be acted on at the Company's annual and
special meetings of shareholders.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
At the annual meeting of shareholders held on June 7, 1999, the Company's
shareholders (including preferred stockholders) (i) elected Class III Directors,
(ii) approved the amendment to the Company's 1997 long-Term Incentive Plan to
adjust the anti-dilution provisions and (iii) approved the amendment to the
Company's Director Stock Option Plan. The following summarizes the number of
votes for and against each nominee and the number of votes withheld and the
number of broker non-votes.
BROKER
NOMINEE FOR AGAINST ABSTAIN NON-VOTE
- --------------------- ---------- --------- --------- ---------
Joseph A. Reeves, Jr. 43,688,235 418,377
Michael J. Mayell 43,688,235 418,377
1997 Long-Term
Incentive Plan 32,412,910 3,534,840 4,563,606 3,595,257
Director Stock
Option Plan 32,523,602 3,415,566 4,572,188 3,595,257
In addition, in conjunction with such annual meeting, SLOPI, the holder of all
of the Company's issued and outstanding Preferred Stock, elected Paul Ching as a
director of the Company pursuant to SLOPI's rights under the certificate of
designation governing the Preferred Stock.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
3.1 Amendment No. 1 to Amended and Restated Bylaws (incorporated by
reference from the Company's Current Report on Form 8-K dated May 5,
1999).
4.1 Note Purchase Agreement dated June 18, 1999, between the Company and
Kayne Anderson Energy Fund, L.P. (incorporated by reference from the
Company's current report on Form 8-K dated June 29, 1999).
4.2 Note Purchase Agreement dated June 22, 1999, between the Company and
EOS Partners, L.P. (incorporated by reference from the Company's
current report on Form 8-K dated June 29, 1999).
4.3 9 1/2% Subordinated Note due June 18, 2001, payable by the Company
to Kayne Anderson Energy Fund, L.P. (incorporated by reference from
the Company's current report on Form 8-K dated June 29, 1999).
26
<PAGE>
4.4 9 1/2% Subordinated Note due June 18, 2001, payable by the Company
to Eos Partners, L.P. (incorporated by reference from the Company's
current report on Form 8-K dated June 29, 1999).
4.5 Form of warrant attached as Annex A to Exhibits 4.3 and 4.4
(incorporated by reference from the Company's current report on Form
8-K dated June 29, 1999).
4.6 Amendments No.'s 1 and 2 to the 1997 Long-Term Incentive Plan
(incorporated by reference from the Company's Registration Statement
on Form S-8, file no: 333-83737).
4.7 Amendment No. 3 dated January 16, 1999, to Amended and Restated
Credit Agreement dated May 22, 1998, by and among the Company, The
Chase Manhattan Bank as administrative agent, and the various
lenders party thereto (incorporated by reference from the Company's
Registration Statement on Form S-8, file no: 333-83737).
4.8 Amendment No. 4 dated April 30, 1999 to Amended and Restated Credit
Agreement dated May 22, 1998, by and among the Company, The Chase
Manhattan Bank as administrative agent, and the various lenders
party thereto (incorporated by reference from the Company's
Registration Statement on Form S-8, file no: 333-83737).
4.9 Amendment No. 1 to Director Stock Option Plan (incorporated by
reference from the Company's Current Report on Form 8-K dated May 5,
1999).
4.10 Rights Agreement dated May 5, 1999, between the Company and American
Stock Transfer & Trust Co., as Rights Agent (incorporated by
reference from the Company's Current Report on Form 8-K dated May 5,
1999).
4.11 Resolution Establishing a Series of Preferred Stock dated May 5,
1999 (incorporated by reference from the Company's Current Report on
Form 8-K dated May 5, 1999).
27.1 Financial Data Schedule.
(b) Reports on Form 8-K.
The Company filed the following Current Reports on Form 8-K relating to
activities during the second quarter of 1999:
On May 13, 1999, the Company filed a Current Report on Form 8-K, reporting
the May 5, 1999 adoption of a Shareholders Rights Plan by the Board of
Directors.
On June 29, 1999, the Company filed a Current Report on Form 8-K,
reporting the completion of the private placements of an aggregate of $20
million of its 9 1/2% convertible subordinated notes due June 18, 2005.
27
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
-----------------------------------------------------------
(Registrant)
Date: August 12, 1999 By: P. RICHARD GESSINGER
------------------------------
P. Richard Gessinger
Executive Vice President and
Chief Financial Officer
By: LLOYD V. DELANO
------------------------------
Lloyd V. DeLano
Vice President
Chief Accounting Officer
28
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM THE MERIDIAN RESOURCE CORPORATION AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 16,886
<SECURITIES> 0
<RECEIVABLES> 26,167
<ALLOWANCES> 121
<INVENTORY> 0
<CURRENT-ASSETS> 48,421
<PP&E> 873,520
<DEPRECIATION> 461,548
<TOTAL-ASSETS> 466,167
<CURRENT-LIABILITIES> 48,681
<BONDS> 265,000
0
135,000
<COMMON> 465
<OTHER-SE> 10,816
<TOTAL-LIABILITY-AND-EQUITY> 466,167
<SALES> 53,909
<TOTAL-REVENUES> 54,275
<CGS> 38,020
<TOTAL-COSTS> 38,020
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 10,608
<INCOME-PRETAX> (849)
<INCOME-TAX> 0
<INCOME-CONTINUING> (849)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (849)
<EPS-BASIC> (.08)
<EPS-DILUTED> (.08)
</TABLE>
